The present invention relates to systems and methods for treating subterranean formations. More particularly, the present invention relates to systems and methods for improved propped fracture geometry for high permeability reservoirs.
Hydrocarbon-producing wells are often stimulated by hydraulic fracturing treatments. Hydraulic fracturing operations generally involve pumping a fracturing fluid into a well bore that penetrates a subterranean formation at a hydraulic pressure to create or enhance one or more cracks, or “fractures,” in the subterranean formation. “Enhancing” one or more fractures in a subterranean formation, as that term is used herein, is defined to include the extension or enlargement of one or more natural or previously created fractures in the subterranean formation. The fracturing fluid may comprise particulates, often referred to as “proppant particulates,” that are deposited in the fractures. The proppant particulates function, inter alia, to prevent the fractures from fully closing upon the release of hydraulic pressure, forming conductive channels through which fluids may flow to the well bore. After at least one fracture is created and the proppant particulates are substantially in place, the fracturing fluid may be “broken” (i.e., the viscosity of the fluid is reduced), and the fracturing fluid may be recovered from the formation.
Hydrocarbon-producing wells also may undergo gravel packing treatments, inter alia, to reduce the migration of unconsolidated formation particulates into the well bore. In gravel-packing treatments, a treatment fluid suspends particulates (commonly referred to as “gravel particulates”) to be deposited in a desired area in a well bore, e.g., near unconsolidated or weakly consolidated formation zones, to form a gravel pack to enhance sand control. One common type of gravel-packing operation involves placing a sand control screen in the well bore and packing the annulus between the screen and the well bore with the gravel particulates of a specific size designed to prevent the passage of formation sand. The gravel particulates act, inter alia, to prevent the formation particulates from occluding the screen or migrating with the produced hydrocarbons, and the screen acts, inter alia, to prevent the particulates from entering the production tubing. Once the gravel pack is substantially in place, the viscosity of the treatment fluid may be reduced to allow it to be recovered.
In some situations, fracturing and gravel-packing treatments are combined into a single treatment (commonly referred to as “frac-pack” operations). In such “frac-pack” operations, the treatments are generally completed with a gravel pack screen assembly in place with the hydraulic fracturing treatment being pumped through the annular space between the casing and screen. In this situation, the hydraulic fracturing treatment ends in a screen-out condition, creating an annular gravel pack between the screen and casing. In other cases, the fracturing treatment may be performed prior to installing the screen and placing a gravel pack.
The effectiveness of hydraulic fracturing is often dependent on the dimensions of the resulting fracture. For example, the resulting fracture is ideally wide enough to allow produced fluids to flow from the reservoir into the well bore at a sufficient rate and long enough to penetrate enough of the reservoir to be fed by an adequate volume of fluid. If the fracture is too narrow, the fracture may be a bottleneck in the production of the fluid; if the fracture is too short, it may not be fed by an adequate volume of fluid from the reservoir.
Attempts have been made at optimizing the geometry of propped fractures in high-permeability formations applying a theory known as “unified fracture design.” This theory attempts to optimize fracture design for a given volume of proppant using pseudo steady-state analysis. However, this methodology relies on having reliable information about the fluid efficiency for a specific fracturing treatment on a reservoir, which may be difficult to achieve, even with extensive diagnostic pumping. As used herein, the term “fluid efficiency” generally refers to the value obtained by dividing the volume of a fracture by the volume of fluid pumped into the fracture. Diagnostic pumping that is used to determine fluid efficiency may add unnecessary time and expense to the fracturing process and/or adversely affect the productivity of the reservoir. Also, by the nature of the fracturing process, fluid efficiency can change during the course of a fracturing treatment. One factor that can affect fluid efficiency is if fracture growth exposes formation layers or surfaces with varying properties. Another factor that can cause fluid efficiency to change during a treatment is changes in treating pressure within a formation. A third factor may be the nature of the fracture's penetration into the formation layers and the degree to which it is a simple single fissure or if the fracture's nature is more complex with multiple or branched fissures. A fourth, but not necessarily final, factor is the degree to which pressure in the fracture affects the porosity and permeability of the fracture face. Softer formations may have changing porosity and permeability along with altered mechanical properties caused by increasing pressure and fracturing fluid invasion.